In order to recover fluid materials such as gaseous or liquid hydrocarbons and the like from geological formations in the earth's crust it is common to drill a well from the surface into the formation. The well is drilled into the ground and directed to the targeted geological location from a drilling rig at the surface. Typically, the drilling rig rotates a drillstring so as to rotate a bottom hole assembly (BHA) that includes a drill bit connected to the lower end of the drillstring. During drilling, a drilling fluid, commonly referred to as drilling mud, is pumped and circulated down the interior of the drillpipe, through the BHA and the drill bit, and back to the surface in the annulus.
Once the bit has reached the formation of interest, it is common to investigate the properties of the formation, such as porosity, permeability, and composition of formation fluids, by obtaining and analyzing a representative sample of rock from the formation. The sample is generally obtained by replacing the drilling bit with a cylindrical coring bit, and the sample obtained using this method is generally referred to as a core sample. Once the core sample has been transported to the surface, the core sample can be analyzed to evaluate the reservoir storage capacity (porosity), the flow potential permeability) of the rock that makes up the formation, the composition of the fluids that reside in the formation, and to measure irreducible water content. These estimates are used to design and implement well completion; that is, to selectively produce certain economically attractive formations from among those accessible by the well. Once a well completion plan is in place, the other strata in the formation are isolated from the target formations, and the fluids within targeted formations are produced through the well. Core samples and information obtained therefrom play an important role in assessing the formation and thus determining how best to produce the formation fluids.
Rotary coring is a common technique for sampling downhole formations. In rotary coring, a hollow cylindrical coring bit is rotated against bottom or, less commonly, the sidewall of the borehole. Coring bits are well known in the art. As the bit penetrates the formation, a core sample is cut and is received in the hollow barrel of the coring bit. After the desired length of the core sample or the maximum capacity of the core bit is reached, the core sample may be broken free of and retrieved to the surface for analysis. Some attempts have been made to provide downhole analysis of the core, but none have been entirely satisfactory.
Even when analysis of the core sample is conducted at the surface, one difficulty remains a particular problem. Namely, the fluid that is used to cool the bit and carry away the formation cuttings, typically a mud, tends to infiltrate the formation rock, including the rock that forms the core sample, because of the large hydrostatic head of fluid that exists downhole.
The drilling fluid typically comprises a water- or oil-based solution in which particles having a desired composition are suspended. The ingredients in the drilling fluid are typically selected to produce a drilling fluid having a desired set of properties. Thus, as is known in the art, drilling fluids typically include weighting agents such as barite to increase density, viscosifiers such as clays to thicken the fluid, and other optional additives such as emulsifiers, fermentation control agents, and the like. While both water- and oil-based muds are common, the present invention relates primarily to water-based muds.
The density of the drilling fluid is typically selected such that at the bottom of the borehole, the hydrostatic head of the drilling fluid will be greater than the fluid pressure naturally present in the formation that is being drilled. It is desirable for the fluid pressure to exceed the formation pressure in order to prevent an uncontrolled or undesired ingress of formation fluids into the well. Because the fluid pressure exceeds the formation pressure, the liquid portion of the drilling fluid can invade the formation, changing the composition of the fluids in the rock in the vicinity of the borehole. When liquid leaks into the formation in this fashion, the solids in the drilling fluid tend to be filtered out on the face of the formation, forming a filter cake, while the liquid portion, known as filtrate, seeps into the pores and interstices in the rock. The same phenomenon often results in the seepage of drilling fluid filtrate into core samples.
One result is that a the contaminated core sample, when retrieved, can no longer provide the desired accurate information about the composition of formation fluids. Hence, when a core is analyzed, it is important to know whether and to what degree the core has been invaded by filtrate from the drilling fluid. To that end, it is common to include a tracer chemical in the drilling fluid when it is important the degree of drilling fluid invasion must be determined.
There are many criteria that are required of an effective tracer material. For example, tracer materials must be selected to avoid undesired effects on drilling fluids and chemicals. Likewise, their absorption characteristics on the filter cake or in the formation, their solubility, and effects on drilling equipment and related facilities are important, as are cost and hazard to drilling and core handling personnel. Hence, there remains a need for a tracer material that is inexpensive and effective and avoids the drawbacks of existing tracer materials.